A choke valve is a particular type of valve commonly used as part of an oil or gas field wellhead. It functions to throttle and reduce the pressure of the fluid flowing through the valve. Choke valves are placed on the production “tree” of an oil or gas wellhead assembly to control the flow of produced fluid from a reservoir into the production flow line. They are used on wellheads located on land (surface) and offshore (platform), as well as on wellheads located beneath the surface of the ocean (subsea). Choke valves common to oil and gas field use are generally described in U.S. Pat. No. 4,540,022, issued Sep. 10, 1985, to Cove and U.S. Pat. No. 5,431,188, issued Jul. 11, 1995 to Cove. A subsea choke valve equipped with pressure transmitters is described in U.S. Pat. No. 6,782,949, issued Aug. 31, 2004 to Cove et al. All of these patents are assigned to Master Flo Valve, Inc. (Master Flo), the owner of this application.
In general, choke valves include:
a valve body having an axial bore, a body inlet (typically oriented as a side inlet to the axial bore) and a body outlet (typically referred to as an bottom or end outlet, aligned with the axial bore);
a “flow trim” mounted in the bore between inlet and outlet, for throttling the fluid flow moving through the body; and
means including a stem and bonnet assembly for actuating the flow trim to open and close the choke valve, and for closing the upper end of the axial bore remote from the outlet.
There are four main types of flow trim commonly used in commercial chokes, each of which includes a port-defining member forming one or more flow ports, a movable member for throttling the flow ports, and seal means for implementing a total shut-off. These four types of flow trim can be characterized as follows:
(1) a needle and seat flow trim comprising a tapered annular seat fixed in the valve body and a movable tapered internal plug for throttling and sealing in conjunction with the seat surface;
(2) a cage with internal plug flow trim, comprising a tubular, cylindrical cage, fixed in the valve body and having ports in its side wall, and a plug movable axially through the bore of the cage to open or close the ports. Shut-off is generally accomplished with a taper on the leading edge of the plug, which seats on a taper carried by the cage or body downstream of the ports;
(3) a multiple-port disc flow trim, having a fixed ported disc mounted in the valve body and a rotatable ported disc, contiguous therewith, that can be turned to cause the two sets of ports to move into or out of register, for throttling and shut-off; and
(4) a cage with external sleeve flow trim, comprising a tubular cylindrical cage having ports in its side wall and a hollow cylindrical external sleeve (also termed external flow collar) that slides axially over the cage to open and close the ports. The shut-off is accomplished with the leading edge of the sleeve contacting an annular seat carried by the valve body or cage.
In the above choke valves, the flow trim is positioned within the choke valve at the intersection of the inlet and outlet. Commonly, the flow trim includes a stationary tubular cylinder referred to as a “cage”, positioned transverse to the inlet and having its bore axially aligned with the outlet. The cage has one or more restrictive flow ports extending through its sidewall. Fluid enters the cage from the choke valve inlet, passes through the flow ports and changes direction to leave the cage bore through the valve outlet.
Maintenance on the deep subsea wellhead assemblies cannot be performed manually. An unmanned, remotely operated vehicle (ROV), is used to approach the wellhead and carry out maintenance functions. To aid in servicing subsea choke valves, choke valves have their internal components, including the flow trim, assembled into a modular sub-assembly. The sub-assembly is referred to as an “insert assembly” and is inserted into the choke valve body and clamped into position.
When the flow trim becomes worn beyond its useful service life due to erosion and corrosion caused by particles and corrosive agents in the produced substances, an ROV is used to approach the choke valve, unclamp the insert assembly from the choke valve body and attach a cable to the insert assembly so that it may be raised to the surface for replacement or repair. The ROV then installs a new insert assembly and clamps it into position. This procedure eliminates the need to raise the whole wellhead assembly to the surface to service a worn choke valve.
In order to efficiently produce a reservoir, it is necessary to monitor the flow rate of the production fluid. This is done to ensure that damage to the formation does not occur and to ensure that well production is maximized. This process has been, historically, accomplished through the installation of pressure and temperature transmitters into the flow lines upstream and downstream of the choke valve. The sensor information is then sent to a remote location for monitoring, so that a choke valve controller can remotely bias the flow trim to affect the desired flow rate. The controller sends electrical signals to actuator means, associated with the choke valve, for adjusting the flow trim.
Fine control over the position of the flow trim is desired. Choke valves are equipped with a means to provide position control. In the most fundamental form, manual operation by a lever or hand wheel is used. To provide remote control of a choke valve's position a variety of actuators, including hydraulic rotary stepping actuators, can be used.
U.S. Pat. No. 6,988,554 issued Jan. 24, 2006 to Bodine et al., describes known hydraulic actuator control systems for the environment of subsea choke valves, noting that it is common for more than one well to be produced through a single flow line, with products from each individual well flow being combined into a common flow line to carry the products to the surface or to combine those products with the products of other flow lines. This patent indicates a difficulty in managing a multiple well completion produced through a single flow line is that not all of the wells may be producing at the same pressure conditions or include the same flow constituents (liquids and gases). Thus, if one well is producing at a lower pressure than the pressure maintained in the flow line, fluid can back flow from the flow line into that well. The loss of production fluids is undesirable, and the pressure changes and reverse flow conditions within that well can damage the well and/or reservoir. Similarly, if one well is producing at a pressure above the flow line pressure, that well may produce at an undesirable flow rate and pressure, again with the potential to damage other wells and/or the reservoir. Thus, management of flow rates and pressures is of critical importance in maximizing the production of hydrocarbons from the reservoir.
In a typical prior art subsea production system, control signals and a hydraulic fluid supply are transmitted along an umbilical from a topside control system to a subsea control module which supplies hydraulic fluid to actuators in the subsea trees. As control valves within the control module receive signals to open or close the choke, the control valves actuate to control the flow of hydraulic fluid to the choke actuator through separate hydraulic lines for opening or closing the choke. A common choke actuator is a hydraulic stepping actuator, which may, for example, take 100 to 200 steps to close. For each step the actuator receives a pulse of hydraulic pressure, which moves the actuator, followed by a release of that pressure, which allows a spring to return the actuator to its initial position. In typical systems, the SCM (subsea control module) is located proximate (e.g., within about 30 feet) to the choke/actuator, and about one second is required for the pressure pulse to travel from the control valve in SCM to the actuator and two seconds are required for the spring to return the actuator to its initial position. With a total of three seconds per step and a total of up to 200 or more steps needed to fully actuate the choke, the time required to fully close or open the choke is considerable. The risk of equipment failure is also increased due to the high frequency of the components being actuated.
Hydraulic or pneumatic stepping actuators commonly used in choke actuation convert the linear motion from hydraulic or pneumatic actuation into rotational motion imparted to an externally threaded stem of the flow trim to open or close the flow trim. These cylinders move linearly in response to a pressurized fluid to stepwise drive actuation components then return to their initial positions using a biasing spring. Thus, each pressure pulse from a directional control valve rotates the choke actuator a certain increment causing linear (i.e., translational), axial adjustment of the flow trim in the choke insert.
Early versions of prior art bi-directional rotary stepping actuators adapted for use with a choke valves are described in U.S. Pat. No. 4,180,238, issued Dec. 25, 1979 to Muchow, and U.S. Pat. No. 4,541,295, issued Sep. 17, 1985 to Cove. The patents describes rotary bi-directional valve actuators including a pair of cranks and ratchet pawls to couple and disengage with one or more ratchet wheels fixed to a stem nut to impart stepwise rotation motion in a clockwise or counterclockwise direction to the stem nut, which in turn moves the valve stem to close or open the valve trim. Hydraulic cylinders are used to drive the dual ratchet mechanisms in opposite directions.
FIGS. 1-3, described below in greater detail, show an embodiment of a Master Flo prior art subsea rotary stepping actuator connected through the stem bonnet assembly to a valve body of a subsea choke. As with the above-mentioned rotary stepping actuators, the angular increments imparted to a stem nut are matched in the clockwise and counterclockwise directions of rotation, and the translational movement imparted to the valve trim with each step is also the same in the opening and closing direction. Thus fine control over the position of the flow trim is set by the angular increments imparted to the stem nut. While fine control can be somewhat addressed by increasing the number of angular increments (steps) needed to open and close the valve, as noted above, for most valves the number of steps to fully open or close the valve is in the order of 100-200 steps, so further increasing the number of steps significantly increases the time needed to open and close the choke valve.